In the oil fields, the accepted rule is not to exceed the maximum allowable casing pressure, hereafter referred to as the MACP, while circulating the kick out of the well.
MACP is, consequently, not exceeded, even when gas is at surface.
At a typical well site, a MACP number (with gas at surface) is posted at the rig on the assumption that all the mud from the annulus has been displaced by gas. A new MACP number can be calculated with gas at surface, by multiplying the “Leak off” gradient with the shoe depth. In this method of calculating the MACP, gas density is ignored, without any consideration being given to the amount of gas in the returning mud giving a very high number for MACP. In actuality, after setting the casing, a leak off test is not usually done. Rather the leak off gradient is assumed to be 18.1 kPa/m. The formation may or may not hold this equivalent leak off gradient. In the absence of a leak off test, there is a concern as to the integrity of the cement job on the casing. Even if a leak off test is conducted, as soon as the drilling continues further, the open hole section exposed below the shoe is not tested to more than the Annular Pressure Loss and the hydrostatic pressure.
Pressure test # 1 is Hydrostatic pressure+Annular Pressure Loss which is a normal pressure on an open hole while drilling.
The first real pressure test on the open hole is the Shut In Drill Pipe Pressure above the hydrostatic pressure.
Pressure test # 2 is Shut In Drill Pipe Pressure plus hydrostatic pressure which is the pressure applied to open hole/well during shut in. This test is like a reverse “Leak off” test. Pressure is applied by the formation instead of a high pressure pump.
Most often the room to MACP which is the difference between Shut In Casing Pressure and Max allowable casing pressure, is a function of kick volume in the well and not a function of abnormal formation pressure. Therefore the bigger the kick taken the more chances that MACP will be reached during the circulation.
During the circulation of the kick the well is subjected to pressure test #3 which is Shut In Drill Pipe Pressure plus Hydrostatic Pressure+Annular Pressure Loss. This is the pressure applied to the open hole during kick circulation. Once the initial circulation pressure is established, without a drop in the drill pipe pressure, the open hole is capable of handling the applied pressure.
Pressure test #4 is where the established pressure is RSPP+Shut In Drill Pipe Pressure+Annular Pressure Loss+Overkill, if any is used.
Modified low choke method of well control presently reads that the MACP should be held constant throughout the circulation. This allows the second kick to be smaller than the first kick. This is only possible if there is a big difference between the Shut In Casing Pressure and the MACP or the MACP is reached when the gas is close to surface.
Usually this does not happen. By the time the first kick reaches surface, the choke being used is wide open and the second choke has to be opened to stay below the MACP. This move results in further lowering the bottom hole pressure due to the fact that the friction pressure through the choke is already dropping as gas cut mud is leaving the wellbore. If this mode of operation is kept up, most of the mud is displaced from the well. In a worst case scenario, the gut line is opened to allow the mud to escape to the flare pit. During this time the drill pipe pressure keeps dropping as there is the least amount of resistance to flow.